Description

Thesis

Results in 2024 will be a sharp improvement from a disappointing 2023 and likely outpace consensus estimates. Improvements in both ship utilization and pricing should drive $200m+ FCF (c.30% yield to the equity). This will reduce net debt to c.$350m by the end of 2024 and simplify the debt stack to only their 13.5% $450m bond, which in turn can start to be called in 2025. 

By the end of 2024 we expect the narrative around PGS to definitively shift from debt concerns to FCF generation, the start of dividends in 2025 and potential upside scenarios from further improvement in 3D seismic demand. 

The low valuation, notably the EV is still close to all time lows, leaves room for a +137% return at 3.5x EV/EBITDA (still below historical 4x average) and a c.12% FCF yield on 2024 numbers. This return is achievable before contemplating a sustained upcycle, as in 2024 we forecast the active 3D vessel count at only a third of the prior peak level.

Business and industry summary

Note: todd1123 has written on PGS in the past, both the debt and equity and is helpful reading for further background. 

PGS sells offshore seismic (primarily 3D) services in two ways, (1) Contract and (2) Multi-client, each with distinct competitors.PGS is currently the only firm to operate both business models. 

Contract work and the supply side for 3D vessels: 

• Contract is straightforward work where the customer pays for a specific survey to be completed by a PGS ship and then solely owns that data. Day rates can be imputed from this segment and are relatable to the way offshore rigs are contracted (albeit generally shorter contracts). 

• Shearwater is the only large 3D vessel owning competitor, and currently they exclusively perform contract work. In rough terms there are 18 active 3D ships now, PGS have 7, Shearwater have 7, and the 4 remaining are split across three firms (see PGS’s chart below). 

• Beyond active ships, Shearwater controls all the industry spare capacity which does not need investment in new streaming equipment (at a cost of $50m+ per ship). Shearwater claim 11 ships could be added at relatively low cost for 3D work, with two caveats: there is some industry skepticism as to whether their oldest ships and equipment are suitable for use in practice (some are more likely to be used for parts) and Shearwater expect several of these ships to be allocated to other lower end seismic work. In Shearwater’s own scenario analysis slide they suggest deploying 14 active 3D ships total (+7) as the top end. At any rate, the consolidation has incentivized Shearwater to be exceptionally disciplined and patient, employing a strategy of only deploying further capacity if utilization is full and at increasing prices. 

• In an increasingly tight market, the industry will start to look towards ships which could potentially carry streaming equipment with the $50m+ investment. This is more of a gray area, but in rough terms PGS have two potential ships and there are a handful of others which could be equipped.

• Taken together, a reasonable estimate is there are 18 currently active + 7 low cost potential additions by Shearwater (although recruiting/training the necessary technical staff will take time) + c.5 ships well suited to being equipped = 30. This would bring the industry back to just over 50% of peak levels. Beyond this, new builds would likely cost c.$300m and take 2+ years to arrive (PGS’s highest spec ships cost $285m at the peak of the last cycle and there has been significant ship building inflation since but, from speaking to industry participants, it would make more sense to build a lower spec vessel as it would be suitable for most jobs).

• Importantly, we are at a point in the cycle where incrementally higher day rates are needed to bring in the incremental capacity, and if demand stalls then capacity (i.e. Shearwater) is able to immediately pause or even reverse supply growth (unlike in the newbuild phase of an upcycle).

Multi-client:

• The nature of seismic surveys means efficiency can often be improved by covering a large geographical area not constrained to a specific operator's license, or additionally covering areas that will come up for future licensing. To manage this dynamic, PGS will survey an area at their own cost and receive revenue in two ways: 1. ‘Pre-funding’ from one or more of the interested parties in a given area (historically this covers slightly more than 100% of PGS’s cash cost of running the ships and currently due to the tight market 120%+). 2. ‘Late sales’ as operators buy relevant data PGS has collected on these surveys, PGS also receive one-off ‘transfer fees’ if a client is acquired. Late sales will often be made relatively quickly after the survey is conducted but also have a long tail (as an operator might buy data when they are newly considering drilling in an area, want analogous data for reference, or if a block is licenced or re-licenced).

• The accumulated data library has value both as it produces a long tail of revenue at minimal incremental cost and, to a lesser extent, combining areas of close geographical coverage can make the data more valuable than in isolation.

• TGS and CGG are the primary competitors in multi-client and neither own or operate 3D vessels (having to rent them from ship owners). TGS is the market leader, having continually invested in their library organically and through acquisition. CGG has struggled for many years with debt and legacy contracts. 

• Given the industry concentration, libraries often covering distinct areas and the complex deal making needed, direct head to head competition for new work appears to be limited and pre-funding pricing moves more in relation to the customer’s alternative of contracting a ship directly, so relates to the contract pricing discussed above.

• The pricing and volume leverage is felt through late-sales from the data library. These tend to be both cyclical, seasonal (Q4 budget usage) and lumpy (due to M&A transfer fees and the relatively large deals involved).

Historically just over 50% of vessel time has been allocated to contract work, although in tighter markets this tends to move higher as customers more aggressively bid for specific survey work rather than coordinating more cost effective multi-client deals (we expect 60%+ of active months to be contract work in 2024). From an accounting perspective this mix shift is a drag on EBITDA (as multi-client cash costs are capitalized), a relatively minor impact to EBIT/EPS, but a boost to revenue and FCF, especially in the near term (as a significant portion of the revenue from multi-client work comes from the late-sales). Due to this mix shift we expect a strong underlying performance in 2024 to allow for beats on all lines except EBITDA, but we think the market should still appreciate strong underlying economics as they will come through in FCF, EPS and revenue.

2023’s transient problems and underlying pricing expansion is a strong set up for 2024

2023’s results have been weak considering the broader positive backdrop for offshore capex and the shares have underperformed. There have been a wide number of issues, that although transient in nature, are symptomatic of a lumpy and cyclical business.

• Late sales, which have almost 100% incremental margins, have been weak y/y in 2023 for PGS and peers. Partly this is comping an unusually strong 2022 due to one-off transfer fees, seemingly large remaining budgets in Q4 2022 for purchasing library data may have pulled forward demand, and TGS believes cost inflation in ‘necessary’ work in 2023 has crowded out data spend which can be deferred. The weakness has not translated into the contract side of seismic, which would have been more worrying. We do not assume a significant pick up here in 2024 y/y as PGS will likely shift some capacity towards contract work so will have less of the newest data to sell.

• Utilization was weak due to worse weather issues than normal and a large contract being canceled (customer permitting issue), with the ship already in transit. Given they are only operating an average of 6.5 ships across 2023, individual issues can be material to the results. 

• Their bond issue in March 2023 avoided further equity issuance or the use of convertibles but coincided with the US banking crisis and a dip in the oil price. This resulted in PGS taking on an unexpectedly high coupon of 13.5% (14% yield including issuing discount) despite strong asset backing, cash flow coverage and an upgraded single B rating. 

• For a period of time investors were concerned about PGS’s maturity profile heading into Q1 2024 and the risk of an equity raise. We don’t think these concerns were well grounded and now with a recent $75m partial refinancing of the term loan as a ‘just in case’ measure (previously flagged as an option by the company), these fears have dissipated. 

In contrast, underlying pricing has been strong, contract revenues per active day are tracking approximately +25% y/y on top of a similar increase in 2022 from lows. We only assume +10% growth in 2024, most of which is already present in current contracting. The recent oil price strength offers some potential upside here.

Improving demand

Seismic historically has been at the tail end of the bullwhip in upstream capex, and the downturn since 2013 has been particularly brutal. IEF data had global upstream capex (including onshore) falling to 40% of peak levels at the 2020 lows, the floating rig count bottomed at 44% of peak in 2021 (much lower in capex spend terms), while the 3D vessel count reached a trough of 27% another year later in 2022. The chart below demonstrates this ‘downcycle within a downcycle’ (includes our estimates for 2023 and 2024). 

There is a reasonable argument this could unwind favorably now that we are in an upcycle. Exploration expenditure has been subdued as discoveries made toward the end of the prior upcycle can be acted on as low hanging fruit. Additionally, after a lengthy downturn where cost savings have been a focus, it is much easier to justify capex with a near-term and high confidence return. This dynamic reverses as the inventory of the most mature projects (brownfield and well defined greenfield) are executed on and operators increasingly ask the question of ‘what next’. Additionally, exploration can lead to more exploration as discoveries in one area incentivizes searching nearby and increases demand for further exploration block bid rounds. 

There is a risk that this upside bullwhip doesn’t take place. Possibly 3D seismic is in structural decline as many of the most prospective areas already have good coverage (i.e. easy 2D replacement is now done) or the appetite for long duration deepwater oil exploration is impaired by the prospect of declining oil demand at some point in the coming decades. Fortunately, due to the good supply side dynamics, we only need modest growth in exploration spend (closer to broader industry capex and the well established uptrend in active deepwater rigs) to keep driving moderate pricing improvements and deliver on high FCF generation.

Less theoretically, despite the weak results from PGS and TGS in 2023, there are clear signs of improving exploration demand.

• The number of offshore exploration lease rounds, one volatile source of future exploration intent, are expected to rise almost +50% in 2023 from a 22 year low in 2022 and to the highest level since 2019 (counted by Rystad and forecasted for 2023 by Schlumberger).

• Schlumberger at JPM’s conference in late June painted a bullish picture of offshore exploration spending, seeing +20% in 2023 (so now outpacing broader upstream capex growth). 

• PGS’s leads data (which is an internal metric so should be taken with a grain of salt) is pictured below. They say it indicates the strongest level of initial interest since 2014 when PGS was operating +50% more ships and the 3D industry was 3x larger. 

The growth of offshore capex vs. broader upstream capex (in particular US onshore) is important for driving a strong and sustained upcycle. Offshore capex underperformed for almost a decade from 2014 but has now started to outgrow the broader industry. While offshore has been making typical down-cycle efficiency gains for many years (particularly on labor costs, which appear to be sticking even as rig costs inflate), US onshore efficiency gains appear to have stalled, perhaps due to depleting the most prospective inventory. The most direct evidence for this reversal in fortunes is the recent performance of the US rig count (flat and then down over the past year) vs. the floating rig count (strongly up) at recent oil prices despite backwardation in the future curve, which in theory should favor shorter cycle onshore projects.

Risks

4D (the fourth dimension is time) or OBN (Ocean Bottom Node) seismic is increasingly being adopted to study reservoirs with increased detail (more for development vs. exploration). It is far more expensive than 3D for a given area (c.10x) despite requiring lower spec ships and cheaper equipment. We think there is a risk that 4D pulls budget from 3D projects even if it can’t be used directly in 3D’s place in the vast majority of cases (due to the cost). More favorably, 4D soaks up low and mid spec ships and there is a significant group of mid spec ships which could potentially do either work, and this tightens 3D vessel supply.

The risk that 3D seismic is in structural decline is discussed above. This is cushioned by the low cyclical starting point.

A declining oil price, in particular Brent futures for the next few years averaging below $70 will increasingly start to hurt offshore industry capex budgets and seismic is still likely to be hurt, even from its depressed starting point. Companies in the offshore space tend to say $60 is the key threshold but we think $70 is more credible for when meaningful deterioration starts.

Management and capital allocation

We have found management to be straightforward and honest. They have a healthy fear of financial leverage, having been struggling with it for many years, and appear laser focused on reducing debt without using further equity or convertible capital. For the next couple of years, debt reduction is an easy capital allocation win as it both de-risks the story and is meaningfully accretive given the high interest costs. That said, PGS is likely to start an initial dividend to be announced with the FY2024 results, so paid in 2025, this should underline the transition from a story focused on balance sheet strain to a narrative of high FCF with additional cyclical upside.

Valuation

Valuing the business at 3.5x EBITDA (modestly below historical averages and consistent with a c.12% FCF yield) in 2024 ($585m) and deducting 2024YE net debt ($350m) works out per share at $1.84/NOK19.8 (+137%). Potentially achievable in 12-18 months.

A two year upside scenario of 4x 2025 EBITDA of $720m (after reactivating an 8th 3D vessel and seeing further moderate pricing gains) and stripping 2025’s FCF out of the net debt (leaving $130m net debt after paying call premiums) would result in $2.99/NOK32.2 (+286%). 

There is no getting away from PGS being both hyper cyclical and currently financially leveraged. However, private market value for their data library has, in the past, offered valuation support even in the worst market conditions. In August 2020 (towards the lows for energy generally) TGS with their strong balance sheet made an opportunistic/hostile bid of $600m for PGS’s library. This more than covers the current debt balance (it did not back then) and would leave the equity holders with the ships. Undoubtedly, in a down market the asset value of the ships will be depressed but even a sharp discount to our estimated newbuild cost for their 7 active ships ($1.9bn) or the depreciated newbuild cost ($1.2bn), would sustain significant equity value. For example, taking 25% of depreciated value and $100m of cash generation over the next 12 months if they enter a bad downcycle (high priced contracts remaining plus working capital release) would leave $0.43/NOK4.6 a share (-45%). 

Catalyst

• Step up in FCF in 2024

• Deleveraging

• Continued offshore exploration spend upcycle